Identification of thermal conductivity properties of formation fluid

ABSTRACT

A downhole well fluid sensing device is disclosed for determining thermal conductivity of a formation fluid produced by a sampled subterranean well, the sensor package having an annulus shaped, elongate body defining a cylindrical fluid sampling space, the elongate body and the sampling space having a common longitudinal center axis. The elongate body has a fluid entrance port that provides well fluid ingress into the fluid sampling space and a fluid exit port that provides well fluid egress out of the fluid sampling space. A heat source is coupled to the elongate body and located along a portion of the fluid path, and the heat source inputs heat into sampled well fluid. Finally, temperature sensing devices located between the fluid entrance port and fluid exit port measure heat conducted to the sampled well fluid, wherein each of the temperature sensing devices is radially spaced from the heat source.

FIELD

The subject matter herein generally relates to a system and method ofmeasuring formation fluid thermophysical properties, and morespecifically to in-situ identification of thermal conductivityproperties of downhole hydrocarbon fluid.

BACKGROUND

During petroleum production operations, the thermophysical properties,such as thermal conductivity, specific heat, and viscosity of thedownhole hydrocarbon fluid often affect production efficiency and cost.High viscosity hydrocarbon fluid production may require the applicationof external heat to reduce the viscosity of the fluid and enable fluidtransport from one place in the reservoir to the well location.Efficiency of production more or less depends upon the external heatingpower and thermal energy transport within a limited time interval.Higher thermally conductive hydrocarbon fluid can effectively transportthe thermal energy further than low thermally conductive fluids. It isdesirable to be able to measure thermal conductivity properties duringwireline logging services and during production processes. The formationfluid thermal conductivity properties that are obtained can be used forwellbore completion, production efficiency control, and optimization.

The thermal conductivity properties of the downhole formation fluidsvaries with pressure, temperature, and chemical composition or molecularweight; the measurement of thermal conductivity can therefore be used toidentify formation fluids. Downhole formation fluids at differentgeometric locations may also have different thermophysical propertiesregarding viscosity, density, thermal conductivity, specific heatcapacity, and mass diffusion. Each of these properties can at leastpartially govern transportation and mobility of crude oils, includinghigh viscosity crude oils, and can consequently impact the recoveryprocess of the crude oils.

Reservoir hydrocarbon fluids may have similar thermal conductivityproperties but different viscosity, density, compressibility, massdiffusivity, and specific heat capacity. Knowing thermal conductivityand other thermophysical properties of the hydrocarbon fluid can atleast partially enable optimization of a well completion design andcrude oil production processes. Presently, the thermal conductivityproperty of the reservoir or downhole hydrocarbon fluid is collected andanalyzed in a surface laboratory with a PVT method, which may take daysor even months. This PVT method tends to reduce the accuracy of anymeasurements due to the passage of time since collection, andenvironmental changes at the collection point(s) which can occur overtime. In-situ detection of these thermophysical properties can improveaccuracy of measurement, improve well completion design, crude oilproduction processes, and production efficiency.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of the present technology will now be described, by wayof example only, with reference to the attached figures, wherein:

FIG. 1 is a perspective view of a subterranean well in accordance withan example embodiment;

FIG. 2 is a front view of a reservoir description tool (RDT) module inaccordance with an example embodiment;

FIG. 3 is a partial view of a formation fluid thermal property sensingsystem in accordance with an example embodiment;

FIG. 4 is a partial view of a formation fluid thermal property sensingsystem that can measure a voltage drop in accordance with an exampleembodiment;

FIG. 5 is a sideview of a formation fluid thermal property sensingsystem that can measure a voltage drop in accordance with an exampleembodiment;

FIG. 6 is a partial view of a formation fluid thermal property sensingsystem that can measure temperature change in accordance with an exampleembodiment;

FIGS. 7A-7C are example graphs of temperature vs. time for high, medium,and low thermal conductive hydrocarbon fluids;

FIG. 8 is an example graph of temperature vs. time for transient thermalresponses from Temp1 and Temp2 sensors;

FIG. 9 is an example graph of K vs. γ;

FIG. 10 is an example graph of normalized temperature vs. time forthermal conductivity analysis;

FIG. 11 is an example graph of transient thermal response from TEMP1 andTemp2 sensors under high and low thermal conductive hydrocarbon fluids;and

FIG. 12 is a flowchart illustrating a method for calculating thermalconductivity of hydrocarbon fluid.

DETAILED DESCRIPTION

It will be appreciated that for simplicity and clarity of illustration,where appropriate, reference numerals have been repeated among thedifferent figures to indicate corresponding or analogous elements. Inaddition, numerous specific details are set forth in order to provide athorough understanding of the embodiments described herein. However, itwill be understood by those of ordinary skill in the art that theembodiments described herein can be practiced without these specificdetails. In other instances, methods, procedures and components have notbeen described in detail so as not to obscure the related relevantfeature being described. Also, the description is not to be consideredas limiting the scope of the embodiments described herein. The drawingsare not necessarily to scale and the proportions of certain parts havebeen exaggerated to better illustrate details and features of thepresent disclosure.

In the following description, terms such as “upper,” “upward,” “lower,”“downward,” “above,” “below,” “downhole,” “uphole,” “longitudinal,”“lateral,” and the like, as used herein, shall mean in relation to thebottom or furthest extent of, the surrounding wellbore even though thewellbore or portions of it may be deviated or horizontal.Correspondingly, the transverse, axial, lateral, longitudinal, radial,etc., orientations shall mean orientations relative to the orientationof the wellbore or tool. Additionally, the illustrated embodiments aredepicted such that the orientation is such that the right-hand side isdownhole compared to the left-hand side.

Several definitions that apply throughout this disclosure will now bepresented.

The term “coupled” is defined as connected, whether directly orindirectly through intervening components, and is not necessarilylimited to physical connections. The connection can be such that theobjects are permanently connected or releasably connected. The term“outside” refers to a region that is beyond the outermost confines of aphysical object. The term “inside” indicate that at least a portion of aregion is partially contained within a boundary formed by the object.The term “substantially” is defined to be essentially conforming to theparticular dimension, shape or other word that substantially modifies,such that the component need not be exact. For example, substantiallycylindrical means that the object resembles a cylinder, but can have oneor more deviations from a true cylinder.

The term “radially” means substantially in a direction along a radius ofthe object, or having a directional component in a direction along aradius of the object, even if the object is not exactly circular orcylindrical. The term “axially” means substantially along a direction ofthe axis of the object. If not specified, the term axially is such thatit refers to the longer axis of the object and can be described as“longitudinally.” The term “temperature sensing device” means a deviceconfigured to sense, determine, measure or derive temperature; the termcan include, but is not limited to, resistance temperature sensor,thermocouple and heat sensor. The term “reservoir description tool”means a device configurable to perform formation pressure testing and/orsampling. Formation pressure testing and/or sampling includes, but isnot limited to, wireline formation pressure testing and/or sampling.

The present disclosure is described in relation to a subterranean wellthat is depicted schematically in FIG. 1. A wellbore 148 is shown thathas been drilled into the earth 154 using a drill bit 150. The drill bit150 is located at the bottom, distal end of the drill string 132 and thebit 150 and drill string 132 are being advanced into the earth 154 bythe drilling rig 126. The drilling rig 126 can be supported directly onland as shown or on an intermediate platform if at sea. For illustrativepurposes, the top portion of the well bore 148 includes casing 134 thatis typically at least partially comprised of cement and which definesand stabilizes the wellbore 148 after being drilled.

As shown in FIG. 1, the drill string 132 supports several componentsalong its length. A sensor package 152 is shown for detecting conditionsnear the drill bit 150, conditions which can include such properties asformation fluid density, temperature and pressure, and azimuthalorientation of the drill bit 150 or string 132. In the case ofdirectional drilling, measurement while drilling (MWD)/logging whiledrilling (LWD) procedures are supported both structurally andcommunicatively. Moreover, the sensor package 152 can detectcharacteristics of the formation surrounding the wellbore 148 proximatethe sensor package 152 such as resistivity and porosity. Another sensorpackage 136 is shown within the cased portion of the well which can besimilarly enabled to sense nearby characteristics and conditions of thedrill string, formation fluid, casing and surrounding formation.Regardless of which conditions or characteristics are sensed, dataindicative of those conditions and characteristics is either recordeddownhole, for instance at the processor 144 for later download, orcommunicated to the surface via telemetry either by wire or wirelessly.If wirelessly, the downhole antenna 138 can be utilized to send data toa local processor 118, via topside antenna 114. There the data may beeither processed or further transmitted along to a remote processor viawire 116 or wirelessly via antennae 114 and 110. The use of coiledtubing 128 and wireline 130 for downhole deployment is alsoschematically indicated and contemplated in the context of thisdisclosure. The possibility of an additional mode of communication iscontemplated using drilling mud 140 that is pumped via conduit 142 to adownhole mud motor 146. Downhole, resistance to the incoming flow of mudis modulated to send backpressure pulses up to the surface for detectionat sensor 124, and from which representative data is sent alongcommunication channel 120 (wired or wirelessly) to one or moreprocessors 118, 112 for recordation and/or processing.

FIG. 2 is an embodiment of the present disclosure that is part of thesensor package 152 of FIG. 1. As shown, module 200 can include areservoir description tool (RDT) module with an in-situ formation fluidthermal identification (FTID) module 220 expanded from the indicateddashed circle 210, showing an example location on the RDT module 200.RDT modules can have many known components, such as a position trackingsystem (PTS) module 250, a dynamic positioning system (DPS) module 251,a temperature and pressure quartz gage sensor (QGS) module 252, aFlow-Control Pump-Out Section (FPS) module 253, a FLDS and magneticresonance imaging (MRI) Lab module 254, and a mobile communicationssystem (MCS) module 255 which are known to persons of ordinary skill inthe art and therefore not described in detail. Finally, a first end 230of RDT module 200 can be furthest downhole, closest to the bit, while asecond end 240 is closest to the surface. Fluid can travel in thedirection from the first end 230 to the second end 240.

FIG. 3 schematically shows more detail about the fluid thermalidentification (FTID) module 220 of FIG. 2. As shown, the FTID module220 can be used to measure the thermal conductivity of the hydrocarbonfluid, the thermal conductivity of the formation fluid, or a combinationof heat capacity and thermal conductivity of the formation fluid, andadditional physical and chemical properties can be combined to make arobust downhole, in-situ analysis possible. The FTID module 220 can beisolated from the general surroundings to prevent contamination fromoutside sources, including unwanted heat transfer. The FTID module canbe created using pipe or similar structure to form a sensor package andcreate a sampling space 320 that runs generally parallel with theoverall RDT module 200. The sampling space 320 can be annulus shaped andcan have an elongate body 330. The elongate body can be an elongatesensor package body. A pump (not shown) can be used to create acontinuous flow of formation fluid through the sampling space 320.Heating element 310 can circumscribe the exterior of the sampling spaceand can heat the sampling space 320. The heating element 310 can be aheat pump. The change in temperature can be measured by temperaturesensing devices 340 placed along the axis 335 in the direction of flowthrough the sampling space 320. As illustrated, temperature sensingdevices 340 can be connected to a thermo sensor data acquisition system337 which can collect or store or collect and store temperature datafrom temperature sensing device 340. Electricity can be supplied to thesystem through contacts 350 and 355, in this case providing power to theheat pump 310, thereby allowing the heat pump 310 to heat the formationfluid in sampling space 320.

FIG. 4 shows another embodiment of the present disclosure fordetermining thermal conductivity characteristics of the hydrocarbonfluid. As shown, the measurement device 400 can be offset and isolatedto assist in preventing contamination from outside sources. A pump (notshown) can cause a continuous flow of formation fluid through thesampling space 420 and body 430. The sampling space 420 can be annulusshaped and can have an elongate body 430. The elongate body 430 can bean elongate sensor package body. In this embodiment of the presentdisclosure, heating element 410 can add heat to the formation fluidswhile the formation fluids flow through the sampling space 420.Temperature sensing devices 440, 442, and 444 can measure the change intemperature of the formation fluids imparted by the heating element 410.While three temperature sensing devices are shown in this embodiment,the number of temperature sensing devices can be limited by their sizeand the size of the sampling space, as well as spacing efficiencies.Further, the location of both the heating element 410 and thetemperature sensing devices can vary within the sampling space, as eachcan be moved so that they reside in the center of the sampling space orthe temperature sensing devices can be moved outward towards the wall,depending on the measurements desired.

With regard to the sampling space generally, the isolated sectiontypically can have a maximum length of 12 (twelve) inches, though theisolated section can have a different length. However, the length canvary above and below these lengths depending on the exact spaceconstraints of individualized setups. The sampling space can furtherentail an outside pipe diameter of 1 (one) inch. Again, the outsidediameter of the pipe can vary depending on the space constraints of theRDT module.

Heating elements or heat sources 310 and 410 can utilize any knownheating method that works within the in-situ drilling environment. Theheating elements or heat sources can be, for example, heat pumps,heating tape, heating wiring, resistance based, microwave-based, laserflashing or radiant heat based, coiled induction heat based, or a heatexchange mechanism. The heating elements or heat sources can be placedoutside the sampling environment as shown in FIG. 3, in the center ofthe sampling environment as shown in FIG. 4, or anywhere in between,depending on the properties being measured. Further, the heatingelements or heat sources can extend along the majority of the samplingspace 320 or 420 or less than a majority of the sampling space 320 or420. The heating elements or heat sources can be concentricallypositioned about the longitudinal center axis of the sampling space. Theheating elements or heat sources can also be positioned within thesampling space on the longitudinal center axis or at a distance from thelongitudinal center axis. Still further, the heating elements or heatsources can be wound about or exteriorly circumscribe an exterior of thesampling space.

The thermal sensors (340 for example) or thermocouples (440 for example)can be any known temperature sensing device, examples of which arewidely known and different temperature sensing devices have differentsensitivities and properties that must be considered when choosing aspecific model. Like the heating elements, the temperature sensingdevices can be placed outside the sampling environment, in the center ofthe sampling environment as shown by FIG. 4, or anywhere in between,depending on the properties being measured. Specifically, thetemperature sensing device can be located between the heat source andthe fluid entrance port so that it can measure heat conducted upstreamfrom the heat source. Another temperature sensing device can be locatedbetween the heat source and the fluid exit port to measure heat conveyeddownstream from the heat source by the sampled well formation fluidflow. The temperature sensing devices can be aligned with one anotherand positioned parallel or substantially parallel to the longitudinalcenter axis of the elongate body and sampling space. In one or moreembodiments, the temperature sensing devices are the arrayedthermocouple sensors, fiber distributed temperature sensors, arrayedfiber Bragg grating sensors, high-frequency temperature sensing devices,and/or arrayed resistivity temperature detectors.

When thermal properties are accurately known, more accurate measurementsare enabled which facilitate improved well completion design and wellproduction. Further, well drilling parameters can be changed forlow-cost operation. Such parameters include the rate of advancementdownhole, the force exerted on the bit, the speed of the bit, and otherparameters recognizable by those persons of skill in the art.Accordingly, knowing thermal conductivity properties, and calculatingthese properties in-situ can enable improved drilling operation as wellas production optimization. Finally, the thermal properties can bemeasured and stored at the RDT module 220, or transmitted, via atransmitter, to the surface for further calculations and actions basedthereupon.

FIG. 5 shows a further example embodiment of the present disclosurehaving heating elements 510 and 515. In this case the entire isolationenclosure 535 is shown. The enclosure 535 can enable the internal flowand heat input to be isolated from other inputs beyond heating elements510 and 515. The heating element 515 can be within the formation fluidand integrated with temperature sensing devices 540, 542, and 544.Formation fluid can enter through a first end, entrance port 533, andcan travel from the bottom 539 of isolation enclosure 535 to the top 537of isolation enclosure 535 and then exit via exit port 531. Heatingelement 515 can provide thermal energy via electrical resistance, withcontacts 550 and 555 providing electricity to the heating element aswell as heat pump 510, as desired. An implementation like the one shownin FIG. 5 can enable an operator to choose to use heating element 510,heating element 515, or a combination of both heating elements dependingon the desired measurement(s) to be made.

FIG. 6 shows another example embodiment of the present disclosure thatcan utilize heating element 610, which runs through the center of thesampling space 620, to heat the sampling space 620.

FIGS. 7A, 7B, and 7C are example graphs showing data obtained from theexample embodiments of the present disclosure and can be directlycollected from example embodiment 600. In FIG. 7A the formation fluidpassing through the sampling space 620 can have a high thermalconductivity, k, which produces the graph shown in FIG. 7A. High k canbe in the range from about 0.1 to about 200 W/m*K. FIG. 7B shows thetemperature readings of a medium thermal conductive formation fluidflowing through sampling space 620. Medium k can be in the range fromabout 5 to about 50 W/m*K. Finally, FIG. 7C shows temperature results ofa low k formation fluid flowing through sampling space 620. Low k can bein the range from about 0.1 to about 5 W/m*K. The ranges discussedherein are in no way limiting and the present disclosure can operateoutside these ranges.

In at least one embodiment within this disclosure, the heating elementcan be made of any thermally conductive and electrically resistivematerial, such as metal or metal alloy. Suitable metals include, but arenot limited to, platinum (Pt), Pt-alloys, tungsten (W), and W-alloys. Apreferred heating element can be protected with an electric insulatingprotecting layer for its application in the electric conductive fluidenvironment. This protecting layer can be a polymeric material, such as,but not limited to, polytetrafluoroethylene (PTFE), polyimide (PI),polyetherketone (PEEK), ultra-high molecular weight polyethylene, andcombinations thereof. In one or more embodiments, the protectingmaterial can have a thickness of 0.01 micrometer to 20 micrometers. Inone or more embodiments, the protecting polymer material such aspolyethylene may have a thermal conductivity greater than 100 W/m*K.

In one or more embodiments, the thermal sensors described herein can beany device capable of detecting a change in fluid properties such asdynamic and steady temperatures and/or can be capable of detectingdynamic thermal response profile along the sensing array. Suitablethermal sensors can include thermocouple (TC) sensors, resistivitytemperature detectors (RTD), platinum resistivity detectors (PRT), fiberBragg grating-based sensors, and/or optical time domain reflectometer(OTDR)-based Brillouin distributed fiber temperature sensors withcentimeter spatial resolution. In one or more embodiments, fiber sensorsfrom Micron Optics or from OZ Optics can be used due to their small sizeand intrinsic insulating properties.

As shown in FIG. 6, two temperature sensing devices 630, 635 can be usedto measure temperature at two separate locations in the sampling space620. These temperatures are plotted on the Y-axis of FIGS. 7A, 7B, and7C, each against time on the X-Axis. This results in FIG. 7A, the high kgraph, indicating that it takes longer for the temperature at 630 tofall and longer for temperature at 635 to rise. The temperature rises at635 for FIG. 7B, the medium k, and FIG. 7C, the low k formation fluidsand are fairly similar at this resolution, with the medium k attaining ahigher temperature and holding it longer. In FIG. 7C the temperaturefalls at 630 more sharply; in other words, quicker, for the low k ofFIG. 7C than for the medium k shown in FIG. 7B.

After the fluid thermal conductivity property has been measured, it canbe used to identify gas, water, and oil. It can also be used to identifydrilling fluid (mud) and mud filtrate. Thermal conductivity can also beused to analyze mufti-phase fluids and to analyze hydrocarbon gascomposition. There is an established relationship between thermalconductivity and the heat capacity, diffusivity, and density of ahydrocarbon fluid. Finally, to avoid long-term fouling and/or scalingissues, the thermal cycles can undergo low to high temperature inducedthermal stress to make the sensors self cleaning.

FIG. 8 represents the results of an embodiment of the present disclosurethat has a central heating wire, 410 like that of FIG. 4. The thermalproperties of the formation fluid can be measured in-situ and theresults are shown in FIG. 8. The graph is an introduced transientthermal dissipation profile analysis. In the embodiment used to createFIG. 8, the heating wire 410 can be integrated with the temperaturesensing device array 440, 442, and 444. The current through the heatingelement 410 can be pulse modulated, initially the transient fluidtemperature will sharply increase, then the temperature can begin todecay. The thermal conductivity of the fluids can be calculated based onthe slope of the decay, indicated by dashed lines 910 and 920. Thehigher the fluid thermal conductivity, the quicker the measured fluid'stemperature reaches to a maximum amplitude of ΔT₂. The higher the fluidthermal conductivity, the greater the decay slope 910 and 920 can be.Either method, i.e., measuring ΔT or the decay slope, can be correlatedto accurately determine the thermal conductivity.

FIG. 11 has normalized the measured transient thermal response curvefrom pulsed thermal excitation with a baseline temperature of theoriginal fluid itself. The absolute temperature change ΔT(t) can be afunction of time. In FIG. 12, this function is depending upon thethermal conductivity k. The slope of the transient thermal responsedecay, γ, is more or less related to the temperature drop of unit timeinterval. The higher of the fluid thermal conductivity, the fast thethermal profile decay, thereby the larger of its decay rate or slope.

Using a temperature sensing device array to detect transient thermalvariation; the heating wire resistance is R(t), the voltage drop will beV(t)=I(0)*R(t); where R(t)=R(0)*(1+αΔT(t)), and transient voltage signalvariation is ΔV(t)=I(0)*R(0)*α*ΔT(t). The theoretical analysis withone-dimensional heating wire thermodynamics can give:

${\rho \; {Cp}\frac{\partial T}{\partial t}} = {{\lambda \frac{\partial^{2}T}{\partial x^{2}}} + G}$

where ΔT(x=0, t)=ζ*t^(1/2), and leads to ΔV(t)=t^(1/2)/(γ·K(t)+β). Thethermal conductivity coefficient K(t) can be written as:

${K(t)} = {\frac{1}{\gamma}*{\left( {\frac{\sqrt{t}}{\Delta \; {V(t)}} - \beta} \right).}}$

When measuring transient temperature variation, ΔT(t), the fluid thermalconductivity is determined by:

${K(t)} = {\frac{1}{\gamma}*\left( {\frac{\sqrt{t}}{{{I(0)} \cdot {R(0)} \cdot \alpha \cdot \Delta}\; {T(t)}} - \beta} \right)}$

where the I(0) and R(0) and heating element thermal expansioncoefficient α are known, such transient thermal detection can providesimple fluid thermal conductivity measurement in-situ for downhole fluidproperty analysis. β is reference value for calibration. One reliableand accurate method for determining K(t) is to use ΔT(t)=ΔT(max), ort=t(max peak). In addition, the decay slope can be defined as γ=ΔT/Δt,obtained after maximum transient amplitude data analysis. It should bepointed out that the measured effective thermal conductivity parameter kis a function of all hydrocarbon components that form formation fluid by

$k = {\sum\limits_{i - 1}^{n}\left( {x_{i}*k_{i}} \right)}$

where k_(i), i=1,2,3, . . . n, is thermal conductivity of eachhydrocarbon component, and x_(i) is fraction of i-th hydrocarboncomposition in the formation fluid mixture.

Based on the above described equations and calculations, the plots of Kversus γ as shown in FIG. 9 can be created, as well as temperatureversus time as shown in FIG. 10. This measured effective thermalconductivity property can be used to evaluate or identify water, oil, orgas, or a mixture of different hydrocarbon fluids. In another case, thiseffective thermal conductivity information can be combined with heatcapacity and viscosity for formation fluid production optimization.

For heating wire inside the fluid, the pulsed heat energy transfers fromheating element to fluid stream. When a pulsed heating wire hasenergized fluid that induces a temperature increase as given by ΔT, theheat flow transfer is:

$q = {{{- k}*\frac{\Delta \; T}{\Delta \; x}} = {h*\left( {T - T_{n - 1}} \right)}}$

Where h is the convective heat transfer coefficient in W/m²K and thermalconductivity is in W/(mk). T_(n-1) is the adjacent dynamic temperaturealong the package tube. Accordingly:

${T(x)} = {T_{n \pm 1} + {\left( {T_{n} - T_{n \pm 1}} \right)*^{{- {(\frac{h}{k})}}x}}}$

When T(x) is plotted, the graph of FIG. 11 can be produced. In thisgraph, the results measured for a fluid with a high thermal conductivitycan be plotted as 1210, the results measured for a fluid with a mediumthermal conductivity can be plotted as 1220, and the results measuredfor a fluid with low thermal conductivity can be plotted as 1230. Theslope of each thermal response from a squared modulated heat energyexcitation reflects speed of the heat energy dissipation to fluid. Highconductive fluid will have a fast energy decay rate. A calibrationtransfer function will be used to interpret the corresponding thermalconductivity, k, versus the slope value.

Referring to FIG. 12, a flowchart is shown of a method for determining athermal conductivity or other thermophysical parameters of formationfluid produced by a sampled subterranean well. The example method 1300is provided by way of example, as there are a variety of ways to carryout the method. The method 1300 described below can be carried out usingthe components illustrated in FIGS. 3 and 4 by way of example, andvarious elements of these figures are referenced in explaining examplemethod 1300. Each block shown in FIG. 12 represents one or moreprocesses, methods, or subroutines, carried out in the example method1300. The example method 1300 can begin at block 1302.

At block 1302 formation fluid is received through a fluid entrance port533 into an annulus shaped, elongate body (330, 430) that defines afluid sampling space (335, 435). The elongate body (330, 430) and thesampling space (335, 435) have a common longitudinal center axis. Then,method 1300 can proceed to block 1304, where thermal energy is appliedto the fluid sampling space (335, 435) by a heat source (310, 410).After which method 1300 can proceed to block 1306 where the temperaturewithin the sampling space is measured by temperature sensing devices(340, 440, 442, 444) concentrically coupled to the elongate body (330,430) but radially separated from the heat source (310, 410). Finally,the method 1300 can proceed to block 1308 where the thermal conductivityis calculated for the formation fluid based on the measured temperaturechanges, and transient maximum response amplitude and decay rate.

At least one embodiment within this disclosure is a downhole well fluidsensing device wherein a plurality of temperature sensing devices (340,440, 442, 444) are aligned, one with the others and positionedsubstantially parallel to the common longitudinal center axis of theelongate body (330, 430) and sampling space (320, 420). The temperaturesensing devices could be arrayed thermocouple sensors; arrayed fiberBragg grating sensors; optical time domain reflectometer (OTDR)-basedBrillouin distributed fiber temperature sensors, or/and arrayedresistivity temperature detectors.

Further to the environmental context of a subterranean well depicted inFIG. 1, the downhole well fluid sensing device for determining thermalconductivity properties of formation fluid produced by a sampledsubterranean well that is disclosed herein can be deployed on a drillstring 132 as illustrated. Alternatively, the downhole fluid sensingdevice for determining thermal conductivity properties of formationfluid produced by a sampled subterranean well can be deployed on coiledtubing 128. The downhole fluid sensing device for determining thermalconductivity properties of formation fluid produced by a sampledsubterranean well can also be deployed on wireline 130. Still further,the downhole fluid sensing device for determining thermal conductivityproperties of formation fluid produced by a sampled subterranean wellcan be utilized in measurement while drilling (MWD) and logging whiledrilling (LWD) procedures.

The embodiments shown and described above are only examples. Manydetails are often found in the art such as the other features of alogging system or production cased well. Therefore, many such detailsare neither shown nor described. Even though numerous characteristicsand advantages of the present sensing technology have been set forth inthe foregoing description, together with details of the structure andfunction of the present disclosure, the disclosure is illustrative only,and changes may be made in the detail, especially in matters of shape,size and arrangement of the parts within the principles of the presentdisclosure to the full extent indicated by the broad general meaning ofthe terms used in the attached claims. It will therefore be appreciatedthat the embodiments described above may be modified within the scope ofthe appended claims.

What is claimed is:
 1. A downhole well fluid sensing device fordetermining thermal conductivity of a formation fluid produced by asampled subterranean well, the sensing device comprising: an annulusshaped, elongate body interiorly defining a substantially cylindricalfluid sampling space, the elongate body and the sampling space having acommon longitudinal center axis; a fluid entrance port providing wellfluid ingress into the fluid sampling space; a fluid exit port providingwell fluid egress out of the fluid sampling space; anupstream-to-downstream fluid flow path for a sampled well fluidextending from the fluid entrance port to the fluid exit port across thesampling space; a heat source coupled to the elongate body and locatedalong a portion of the fluid flow path between the fluid entrance portand the fluid exit port for inputting heat into the sampled well fluid;and a plurality of temperature sensing devices coupled to the elongatebody and located between the fluid entrance port and fluid exit port formeasuring heat conducted to the sampled well fluid, wherein each of theplurality of temperature sensing devices is radially spaced from theheat source and wherein the measurement is used to calculate the thermalconductivity of the formation fluid.
 2. The downhole well fluid sensingdevice of claim 1, wherein the heat source is concentrically positionedabout the longitudinal center axis of the sampling space.
 3. Thedownhole well fluid sensing device of claim 2, wherein the heat sourceis centrally positioned longitudinally within the sampling space on thelongitudinal center axis.
 4. The downhole well fluid sensing device ofclaim 2, wherein the heat source is positioned within the sampling spaceat a distance from the longitudinal center axis.
 5. The downhole wellfluid sensing device of claim 2, wherein the heat source is positionedoutside the annulus shaped, elongate body at a distance from thelongitudinal center axis.
 6. The downhole well fluid sensing device ofclaim 5, wherein the heat source is a coiled heating element wound aboutan exterior of the annulus shaped, elongate body, and wherein the heatsource is one or more of a resistive heating tape, an inductionmechanism, a microwave mechanism, and a laser flush based heatingmechanism.
 7. The downhole well fluid sensing device of claim 2, whereinthe heat source exteriorly circumscribes the annulus shaped, elongatebody.
 8. The downhole well fluid sensing device of claim 1, wherein theheat source comprises a plurality of heat inputs positioned at differentlocations about the elongate body.
 9. The downhole well fluid sensingdevice of claim 1, wherein at least one of the plurality of temperaturesensing devices is located between the heat source and the fluidentrance port for measuring heat conducted upstream from the heatsource, and at least one of the plurality of temperature sensing devicesis located between the heat source and the fluid exit port for measuringheat conveyed downstream from the heat source by sampled well fluidflow.
 10. The downhole well fluid sensing device of claim 1, wherein theplurality of temperature sensing devices is aligned and positionedsubstantially parallel to the common longitudinal center axis of theelongate body and sampling space.
 11. The downhole well fluid sensingdevice of claim 1, wherein the heat source extends along a majority ofthe elongate body.
 12. A method for determining a thermal conductivityof a formation fluid produced by a sampled subterranean well, the methodcomprising: receiving, through a fluid entrance port, formation fluidflow in an annulus shaped, elongate body interiorly defining asubstantially cylindrical fluid sampling space, the elongate body andthe sampling space having a common longitudinal center axis; applyingthermal energy to the fluid sampling space, wherein the thermal energyis applied by a heat source; measuring a temperature change over time ata plurality of temperature sensing devices concentrically coupled to theelongate body, wherein the plurality of temperature sensing devices arelongitudinally spaced along the sampling space and radially separatedfrom the heat source; and calculating the effective thermal conductivityof the formation fluid based on the temperature change profile andtransient temperature response decay slope.
 13. The method ofdetermining the thermal conductivity of a formation fluid of claim 12,further comprising pumping the formation fluid, via a fluid exit port,out of the fluid sampling space, wherein a transient relativetemperature amplitude is measured over time with a high-frequencytemperature sensing device.
 14. The method of determining the thermalconductivity of a formation fluid of claim 12, wherein applying thermalenergy comprises applying a pulse-modulated thermal energy to theformation fluid along a portion of the substantially cylindrical fluidsampling space, wherein the pulse of thermal energy is applied by a heatsource.
 15. The method of determining the thermal conductivity of aformation fluid of claim 12, further comprising the step of: altering,in-situ, a production optimization parameter based on the calculatedthermal conductivity, wherein during time modulated external heat energyexcitation, multi-point thermal sensors measure transient temperatureresponse profiles and the thermal decay slope is used for thermalconductivity analyses.
 16. The method of determining the thermalconductivity of a formation fluid of claim 12, further comprising thestep of: transmitting the calculated thermal conductivity by telemetryto a surface data processing system for use in altering a drilling orproduction parameter.
 17. The method of determining the thermalconductivity of a formation fluid of claim 12, wherein the heat sourceis centrally positioned within the sampling space on the longitudinalcenter axis.
 18. The method of determining the thermal conductivity of aformation fluid of claim 12, wherein the heat source is positionedwithin the sampling space at a distance from the longitudinal centeraxis.
 19. The method of determining the thermal conductivity of aformation fluid of claim 12, wherein the heat source is positionedoutside the annulus shaped, elongate body at a distance from thelongitudinal center axis.
 20. The method of determining the effectivethermal conductivity of a formation fluid of claim 12, wherein thethermal energy is applied as a modulated energy pulse with electriccurrent.